Apparatus and Method for Underbalanced Drilling and Completion of a Hydrocarbon Reservoir

ABSTRACT

A system and method for underbalanced drilling and completion of a hydrocarbon reservoir is disclosed. The system prevents formation damage by using a solids-free, non-wetting phase drilling fluid while maintaining underbalanced conditions throughout the entire drilling and completion phase of the operation. By preventing formation damage, this system provides an alternative or supplement to hydraulic fracking.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority to and the benefit of U.S. ProvisionalPatent Application No. 62/040,285 entitled “Apparatus and Method forUnderbalanced Drilling and Completion of a Hydrocarbon Reservoir” filedon Aug. 21, 2014, the entire disclosure of which is incorporated byreference herein.

FIELD

Embodiments of the present invention are generally related to a systemand method for underbalanced drilling and completion of a hydrocarbonreservoir and in particular, to a system and method for underbalanceddrilling and completion of a hydrocarbon reservoir while maintainingunderbalanced conditions throughout the entire drilling and completionphase of the operations.

BACKGROUND

Conventional hydrocarbon reservoir drilling employs overbalanceddrilling, cementing of the steel casing of the wellbore, and a kill mudapproach for well completion. In overbalanced drilling, the wellbore iskept at a pressure higher than the pressure of the hydrocarbon formationto prevent formation fluid from entering the well. These conventionaltechniques cause formation damage to the hydrocarbon reservoir.Formation damage results in reduced reservoir permeability which limitswell productivity. Furthermore, formation damage caused by overbalanceddrilling can so reduce reservoir permeability that hydraulic fracturingis required to yield an economically viable well.

Formation damage is caused by foreign fluids and/or solids entering ahydrocarbon bearing reservoir during the drilling and/or completionphase of the operation. Such foreign fluids can cause: (1) capillarypressure water blocks to form within the pores, pore throats and/orfracture apertures within the reservoir; (2) expandable clays such asSmectite or mixed-layer clays (such as Chlorite-Smectite) to expandwithin the pores, pore throats and/or fracture apertures within thereservoir; or (3) solids contained within the drilling mud (such as mudadditives or rock cuttings) to be injected into the pores, pore throatsand/or fracture apertures within the reservoir. All such types offormation damage reduce the permeability of the reservoir which in turnreduces the ability of hydrocarbons to flow through the reservoir andinto the wellbore, thereby reducing the productivity of a well. When theamount of formation damage is significant, the reservoir must behydraulically fractured in order to mitigate the formation damage andobtain economic rates of production.

A system and method for underbalanced drilling (“UBD”) and completion ofa hydrocarbon reservoir is disclosed. In underbalanced drilling, thepressure in the wellbore is kept lower than the fluid pressure in theformation being drilled. The system and method for underbalanceddrilling and completion of a hydrocarbon reservoir maintainsunderbalanced conditions throughout the entire drilling and completionphase of the operation, thereby not causing formation damage to thehydrocarbon reservoir which would reduce reservoir permeability and thuslimit well productivity. By preventing formation damage, the need tohydraulically fracture stimulate the hydrocarbon bearing reservoir maybe eliminated in many cases. As such, the system and method provides analternative or supplement to hydraulic fracture stimulations. In oneembodiment, the system and method uses a solids free, non-wetting phasedrilling fluid and does not cement a casing string across the producingformation in the wellbore. Maintaining underbalanced conditionsthroughout the drilling and completion phase of the operation, togetherwith not cementing a string of casing in the producing formation andusing only non-wetting phase drilling and completion fluids while in thetarget zone, prevents formation damage from occurring.

SUMMARY

A “Cradle-to-Grave” system and method to prevent formation damage in oiland/or gas reservoirs by drilling with a solids-free, non-wetting phasedrilling fluid, while maintaining underbalanced conditions throughoutthe entire drilling and completion phase of the operation, is disclosed.

In one embodiment, an advanced method of drilling a hydrocarbon wellboreis disclosed, the method comprising: using at least one of anoverbalanced and an underbalanced fluid column to drill a wellbore to anupper portion of a hydrocarbon reservoir; installing and cementing acasing string inside the wellbore to the upper portion of thehydrocarbon reservoir; providing a mechanical fluid control valve in thecasing string segment above a predetermined target producing zone; usingan underbalanced fluid column, drilling and completing the targetedproducing zone using a solids-free and non-wetting phase drilling fluidmaintained below the pressure of the hydrocarbon reservoir; injectingnitrogen into the drilling fluid as needed to reduce the hydrostatichead of the drilling fluid and enable the underbalanced drilling to bemaintained; and circulating the drilling fluid and nitrogen, and anyproduced fluids and rock cuttings, through a series of surface processequipment designed to separate oil, gas, water and rock cuttings underpressure.

In another embodiment, a method of drilling for recovery of hydrocarbonscomprising oil and natural gas from a hydrocarbon reservoir isdisclosed, the method comprising: using an overbalanced or underbalancedfluid column to drill a hydrocarbon wellbore to an upper portion of ahydrocarbon reservoir; installing and cementing a casing string insidethe wellbore; providing a downhole deployment valve in a lowermostcasing string segment and above a projected hydrocarbon producing zone;using an underbalanced fluid column, drilling and completing thetargeted producing zone using a solids-free and non-wetting phasedrilling fluid maintained below the pressure of the hydrocarbonreservoir; providing nitrogen as needed in the drilling fluid to reducethe hydrostatic head of the drilling fluid; circulating the nitrogenthrough an annulus formed by a second casing; circulating the drillingfluid and nitrogen, and any produced fluids and rock cuttings, throughsurface process equipment designed to separate oil, gas, water and rockcuttings under pressure.

In yet another embodiment, a system for drilling for recovery ofhydrocarbons comprising oil and natural gas from a hydrocarbon reservoiris disclosed, the system comprising: a wellbore extending at least to anupper portion of a hydrocarbon reservoir; a casing string disposedinside the wellbore; a mechanical fluid control valve disposed in thecasing string segment and above a target producing zone; utilizing asolids-free and non-wetting phase drilling fluid maintained below thepressure of the hydrocarbon reservoir; and wherein the drilling fluid ismaintained below the pressure of the hydrocarbon reservoir to enableunderbalanced drilling; wherein nitrogen is injected into the drillingfluid as needed to reduce the hydrostatic head of the drilling fluid andenable the underbalanced drilling to be maintained; and whereinnitrogen, hydrocarbons, and drilling fluid are produced and treatedunder pressure with surface process equipment.

This Summary is neither intended nor should it be construed as beingrepresentative of the full extent and scope of the present disclosure.The present disclosure is set forth in various levels of detail in theSummary as well as in the attached drawings and the Detailed Descriptionof the Invention, and no limitation as to the scope of the presentdisclosure is intended by either the inclusion or non-inclusion ofelements, components, etc. in this Summary of the Invention. Additionalaspects of the present disclosure will become more readily apparent fromthe Detailed Description, particularly when taken together with thedrawings.

The above-described benefits, embodiments, and/or characterizations arenot necessarily complete or exhaustive, and in particular, as to thepatentable subject matter disclosed herein. Other benefits, embodiments,and/or characterizations of the present disclosure are possibleutilizing, alone or in combination, as set forth above and/or describedin the accompanying figures and/or in the description herein below.However, the Detailed Description of the Invention, the drawing figures,and the exemplary claim set forth herein, taken in conjunction with thisSummary of the Invention, define the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and constitute apart of the specification, illustrate embodiments of the invention andtogether with the general description of the invention given above, andthe detailed description of the drawings given below, serve to explainthe principals of this invention.

FIG. 1 depicts a circulation schematic of one embodiment of theunderbalanced drilling method and system;

FIG. 2A depicts a one embodiment of the underbalanced drilling methodand system using a wellbore single casing arrangement; and

FIG. 2B depicts another embodiment of the underbalanced drilling methodand system using a wellbore dual casing arrangement;

It should be understood that the drawings are not necessarily to scale.In certain instances, details that are not necessary for anunderstanding of the invention or that render other details difficult toperceive may have been omitted. It should be understood, of course, thatthe invention is not necessarily limited to the particular embodimentsillustrated herein.

To assist in the understanding of one embodiment of the presentinvention the following list of components and associated numberingfound in the drawings is provided.

# Component 10 System 12 Drilling Rig 14 Rotating Control Device (RCD)16 Blow Out Preventer 18 Downhole Deployment Valve (DDV) 20 Manifold 224-Phase Separator 24 Flare Line 26 Flare Stack 28 Oil Line 29 Water Line30 Solids Dump Line 32 N₂ Source 34 Command Trailer 36 Frac TanksCascaded together to contain produced oil 37 Frac Tanks Cascadedtogether to contain produced water 38 Tanks Containing Solids-Free,Non-Wetting Phase Drilling Fluid 40 Rig Tanks 42 Rig Pumps 44 DrillingFluid 46 Reserve Pit 48 Oil and/or Gas Bearing Reservoir 50 Mudlogger'sTrailer 60 Single Casing Wellbore 62 Surface Casing 64 Last Casing Runabove Target Formation 66 Annulus (single) 68 Drill Bit 70 Drill Pipe 72N₂ injected with Drilling fluid 74 N₂ Return Flow up the Annulus 80Concentric Casing Wellbore 82 Tie-Back Liner 84 Outer Annulus 86 InnerAnnulus 88 Ports in Tie-Back Liner 90 N₂ Injected into Outer Annulus 92N₂ Return Flow Up Inner Annulus

DETAILED DESCRIPTION

FIG. 1 depicts a circulation schematic of one embodiment of the drillingsystem 10. A drilling rig 12 sits atop the oil and/or gas bearingreservoir 48. The drilling rig 12 is connected by piping to the rotatingcontrol device (RCD) 14. A rotating head is required at the surface toprovide a seal that diverts produced fluids to the 4-phase separator 22,via a manifold 20, to allow the drill string to continue drilling (i.e.rotating) during underbalanced conditions. The RCD also connectsdownstream from the blow out preventer 16 which connects downstream tothe downhole deployment valve 18 before reaching into the oil and/or gasbearing reservoir 48.

The 4-phase separator 22 separates the oil, water, solids, and gas. Thegas feeds into the flare line 24 before being burned off in the flarestack 26. The solids feed into the solids dump line 30 which feeds intothe mudlogger's trailer 50. The water feeds into the water line 29 whichdeposits into the hydraulic fracturing (aka “frac”) tanks cascadedtogether to contain produced water 37. The oil feeds into the oil line28 which is deposited into the frac tanks cascaded together to containproduced oil 36.

Tanks containing solids-free, non-wetting phase drilling fluid 38 feedinto the rig tanks 40. The rig tanks keep a positive suction head on therig pumps 42 which pump a combination of the non-wetting phase drillingfluid and nitrogen gas (“N₂”) from the N₂ source 32 which combine indrilling fluid 44 line. The destination of the produced oil, water,solids, and/or produced gas may be controlled at the command trailer 34.

The reserve pit 46 is used to store any spare waste mud, base oil, orbrine.

Conventional overbalanced drilling techniques rely on the hydrostatichead created by a heavy column of drilling mud to exert a pressure atdepth that is equal to or greater than the formation pressure of thereservoir, thereby preventing formation fluids (oil, gas and/or water)from entering the wellbore while drilling. The pressure at depth thatresults from the hydrostatic head of the heavy column of mud commonlyexceeds the formation pressure, resulting in the introduction of foreignfluids and/or solids into the hydrocarbon bearing reservoir 48. It isthis entry of foreign fluids and/or solids into the reservoir thatcauses the formation damage.

Even if a well is drilled underbalanced, heavy kill mud is commonlypumped into the wellbore prior to completing the well. The heavy killmud prevents the well from flowing when the drill pipe is removed fromthe wellbore. The kill mud has the same damaging effects as drilling thewell overbalanced. As an alternative to using heavy kill mud, the use ofa mechanical fluid control valve, such as a DDV 18, allows a well to beshut-in mechanically at depth by closing a hydraulically operatedflapper valve via the use of controls at the surface. The use of the DDV18 allows the operator to prevent the well from flowing mechanically (asopposed to hydraulically) and thereby eliminates the need to pump thekill mud. The DDV 18 allows for the prevention of the formation damagethat would otherwise be caused by the kill mud. It is the use of the DDV18 that allows underbalanced conditions to be maintained during tripsfor bit replacement and/or maintenance and when the drilling rig 12 ismoved off the well in order to move in the completion rig.

Completing a well commonly involves running steel casing into thewellbore and cementing it in place prior to perforating the casing toestablish production through the perforations or through which tofracture stimulate the formation in one or more stages. The process ofcementing the casing into the wellbore involves pumping wet cement intothe well so that it is forced up the annulus 66 (space between theoutside of the casing and open hole) until cement reaches the desiredheight. The particulate matter making up the cement and the liquidcement filtrate are forced into the formation and cause formation damagein the same manner as the drilling mud described above.

Hydrocarbon reservoirs 48 are either “water-wet” or “oil-wet”. Thoseterms refer to the type of fluid that adheres to the surface of rock,not the type of fluid that the reservoir is capable of producing. If thereservoir 48 is water-wet, the wetting phase is water and similarly ifthe reservoir rock is oil-wet, the wetting phase is oil. Mosthydrocarbon bearing reservoirs 48 are water wet, although some are oilwet and some have a mixed wettability (i.e. partially oil wet andpartially water wet). Natural gas is never the wetting phase. During thedrilling and completion process, the reservoir will imbibe the wettingphase fluid if that phase fluid is present in the drilling or completionfluids. For example, if a water-wet, oil bearing reservoir is drilledwith a water based drilling mud, then the reservoir will imbibe thewater contained within the drilling mud. This imbibition process drivesthe oil within the reservoir away from the wellbore. This process isanalogous to the process used to water flood reservoirs whereby water isinjected into an injection well so that the water will drive the oilwithin the reservoir toward other nearby producing wells. In a damageprone reservoir (that is not intended to be a water flood operation),once the hydrocarbons are pushed out away from the wellbore duringdrilling and completion, any formation damage caused by that imbibedfluid or the solids contained therein, will impede the return flow ofthose hydrocarbons back toward the producing wellbore. This impedance ofthe return flow is typically not a complete barrier to return flowtoward the producing wellbore, but rather a relative decrease in flowcompared to an otherwise non-damaged reservoir. In water wet orpartially water wet reservoirs, however, imbibed water can createsignificant formation damage in the form of a capillary pressure waterblock. Accordingly, in order to maximize the production rate from awell, it is imperative to drill and complete the well using only asolids free, non-wetting phase fluid.

Generally, a “Cradle-to-Grave” process to prevent formation damage inoil and/or gas reservoirs by drilling and completing the well with asolids-free, non-wetting phase fluid, while maintaining underbalancedconditions throughout the entire drilling and completion phase of theoperation, is disclosed. The application of this Cradle-to-Grave processprevents formation damage from occurring, therefore, it is not necessaryto mitigate any formation damage and economic rates of production may beachieved without the need to hydraulically fracture the reservoir.

FIG. 2A depicts a cross sectional view of a single casing wellbore 60which uses nitrogen to maintain balancing conditions. The underbalanceddrilling method and system, in one embodiment, may use such a casingarrangement. The drill bit 68 is contained within the surface casing 62,which runs from the earth's surface, and the last or most distal casingrun 64. The drill bit 68 drives interior or within the casing run 64 toreach the hydrocarbon reservoir 48. Nitrogen is injected under pressuredownhole with the drilling fluid 72, exiting the drill bit 68 andreturning up the annulus 74 formed between the casing and the drillpipe. The N₂ returns 74 to the surface via the single annulus 66 outsidethe drill pipe 70 and inside the last casing run 64.

FIG. 2B depicts a cross sectional view of another embodiment of awellbore casing arrangement of the underbalanced drilling method andsystem, comprising a concentric casing (aka dual casing) wellbore 80.The underbalanced drilling method and system may alternatively use sucha casing arrangement. The surface casing 62 runs from the earth'ssurface and comprises the last casing run 64. Interior to the lastcasing run 64 is, concentrically, outer annulus 84, the tie-back liner82, and the inner annulus 86. N₂ is injected 90 down the outer annulus84, where it flows through the ports in the tie-back liner 88, and isurged upwards through inner annulus 86 by pressure of the hydrocarbonreservoir 48 and the buoyancy of the nitrogen gas. The buoyancy of thenitrogen gas, among other things, reduces the hydrostatic head of thefluid column. The drill pipe 70 is positioned within the inner annulus92 and attaches to the drill bit 68, which drives further into the earththan the annuli 84, 86.

In yet another embodiment, nitrogen may be injected down the innerannulus 86 where it flows through the ports in the tie-back liner 88,and is urged upwards through the outer annulus 84 by pressure of thehydrocarbon reservoir 48 and the buoyancy of the nitrogen gas. In oneembodiment, no drilling or completion fluid which is overbalanced withrespect to the hydrocarbon formation pressure comes in contact with thehydrocarbon formation.

With respect to FIGS. 1 and 2, the elements of the system and method arediscussed below.

Pre-Drill Modeling for UBD Conditions

Pre-drill modeling is conducted to determine and assess drillingconditions as suitable for underbalanced drilling.

Training Rig and 3^(rd) Party Contractors in UBD

Because UBD is an atypical drilling method, rig and third-partycontractors are provided special training in UBD.

Drill to the Top of the Targeted Pay Zone Using ConventionalOverbalanced Drilling Techniques

Conventional overbalanced techniques are used until the targeted zone isreached, to include conventional cementing of the casing string withinthe wellbore, at least within the upper portion of the wellbore. Oneembodiment of a wellbore includes an upper (vertical well) portiondrilled using conventional overbalanced techniques and lower portion(horizontal portion), in targeted zone, drilled using underbalanceddrilling. Other embodiments include using conventional overbalancedtechniques until the targeted zone is reached as discussed above, withthe lower portion using underbalanced techniques but also in a verticalwellbore. An alternate embodiment of the method to drill theunderbalanced portion of the well comprises the use of coiled tubing, asknown to those skilled in the art. In an alternate embodiment, the DDV18 is located at or near the surface, or in any location wherein thewell may be shut without having to kill the well or snub out of thewell.

An alternate embodiment comprises any mechanical fluid control valvethat serves the same function as the DDV 18, that is, any device thatallows the well to be shut-in mechanically from within the wellbore, asopposed to using heavy kill mud to kill the well.

Set Casing Immediately Above or Just into the Targeted Pay Zone

The last casing run includes a DDV 18, discussed in more detail below.In certain circumstances, including but not limited to areas in whichsignificant water production is anticipated, it may be preferable to usea concentric casing design created by a tie back liner 82 to the surfaceto create a dual annulus 90, 92. The drill pipe is then run inside thetie back liner 82. The underbalanced portion of the well is drilled witha drill string that runs inside the liner. The two annuluses are: (1)between the drill pipe and the liner 86, and (2) between the liner andthe casing 84.

The liner includes ports or check valves 88 at depth that allow nitrogento be circulated through the dual annulus system rather than through thedrill pipe. This reduces corrosion to the bottom hole assembly as anyoxygen contained in the injected nitrogen does not materially contactthe bottom hole assembly. In a horizontal wellbore targeting a naturallyfractured reservoir, circulating nitrogen through the concentric casing(as opposed to through the drill pipe) reduces the vertical loss ofnitrogen to the formation via the fracture system. The switch tounderbalanced drilling occurs prior to the drilling out of cement in thelast casing run above the targeted horizon.

Drill and Complete with Solids-Free, Non-Wetting Phase Fluid

In one embodiment, the solids-free, non-wetting phase fluid comprisescrude oil (preferably lease crude oil), pure mineral oil or lowvolatility and toxicity (LVT) drilling fluid. LVT is a mineral oil baseddrilling fluid, and is not pure mineral oil. Water is not used unlessthe wetting phase of the reservoir is oil, i.e. an oil wet reservoir. Nocement is used in the productive zone.

Continuous Pressure Monitoring During Drilling

Nitrogen is injected into the drilling fluid 72 as it is pumped downholeto reduce the density of the drilling fluid. See FIG. 2A. The amount ofnitrogen required (if any) depends upon the reservoir conditions andwellbore 60 configuration. Nitrogen lowers the hydrostatic head of thedrilling fluid, thereby enabling underbalanced drilling. The nitrogen isavailable at all times to maintain underbalanced conditions. If thereservoir pressure at all times exceeds the pressure exerted by thecolumn of solids-free, non-wetting phase drilling fluid, the injectionof nitrogen may not be required. In other embodiments, other methods ofinjection are used, such as using a parasite tube run on the outside ofthe casing.

Downhole Deployment Valve 18

The DDV 18 (or any other form a mechanical fluid control or shut-invalve) is cemented in the last casing run above the target zone (in thevertical section if the well is a horizontal well). If using theconcentric casing well design 80, the DDV 18 is put into the inner linerthat is tied back to the surface, which is not cemented into place. TheDDV 18 eliminates the need to “kill” the well.

A DDV 18 generally allows an upper section of a wellbore to be isolatedfrom a tower section. DDV 18 technologies and operations are describedin the following documents, each of which are incorporated by referencein their entirety: U.S. Pat. No. 7,690,432 to Noske et al. issued Apr.6, 2010; U.S. Pat. No. 7,475,732 to Hosie et al.; U.S. Pat. No.7,451,809 to Noske et al., issued Nov. 18, 2008; U.S. Pat. No. 7,350,590to Hosie et al., issued Apr. 1, 2008; and U.S. Pat. No. 7,178,600 toLuke et al. issued Feb. 20, 2007.

Rotating Head Blowout Preventer (BOP), Rotating Control Head or Device(RCH or RCD) 14

Rotating Head Blowout Preventer 16 (BOP) technologies and operations aredescribed in the following documents, each of which are incorporated byreference in their entirety: U.S. Pat. No. 8,353,337 to Bailey et al.issued Jan. 15, 2013; U.S. Pat. No. 8,113,291 to Bailey et al. issuedJan. 13, 2009; U.S. Pat. No. 7,934,545 to Bailey et al., issued May 3,2011; U.S. Pat. No. 7,836,946 to Bailey et al.; U.S. Pat. No. 7,380,590to Hughes et al. issued Jun. 3, 2008; U.S. Pat. No. 7,258,171 toBourgoyne et al. issued Aug. 21, 2007; U.S. Pat. No. 7,159,669 toBourgoyne et al. issued Jan. 9, 2007; U.S. Pat. No. 7,040,394 to Baileyet al. issued May 9, 2006; and U.S. Pat. No. 6,470,975 to Bourgoyne etal. issued Oct. 29, 2002.

4-Phase Separator 22, Real Time Data Acquisition and Flare System

A 4-Phase Separator 22 (water, oil, gas, solids i.e. drill cuttings),Real Time Data Acquisition and Flare System enable drilling ahead safelywhile producing. In one embodiment, these components enable a productionof up to 100 MMCFPD+40,000 bbls fluid per day. A 4-phase separator 22 isdescribed in U.S. Pat. No. 7,654,319 to Chitty et al. issued Feb. 2,2010, which is incorporated by reference in its entirety. As appreciatedby one skilled in the art, any capacity of 4-phase separation could beused based on the wellbore flow characteristics.

The 4-phase separator 22 in one example comprises at least a pressuretank, a flow line, a check valve, a flare stack 26, an electricalgenerator, a glycol heater, an injection pump and a rotating blowoutpreventer 16, as well as other safety devices such as level and pressurecontrols.

Tankage Available at the Surface to Handle High Rates of FluidProduction During Drilling

Frac tanks are cascaded together to contain produced fluid 36.

Well Completion

In one embodiment, the well is a barefoot completion, i.e. no casing orliner is set across the reservoir formation, thereby allowing producedhydrocarbon fluids to flow directly into the wellbore. In anotherembodiment, the well is completed using any technique known to thoseskilled in the art, to include a slotted liner, a pre-holed liner, apre-cut liner and a pre-drilled liner.

Although the disclosed invention has been discussed as part of an effortto extract oil and/or gas, it could be used to mine any kind ofhydrocarbon. Although the disclosed invention discussed using N₂ gas,any gas known to a person skilled in the art could be used. As will beappreciated, it would be possible to provide for some features of theinventions without providing others.

Underbalanced Drilling Operations

Several aspects of underbalanced drilling operations as used in themethod and system of the disclosure differ from conventional (i.e.overbalanced) drilling. The following specific UBD operations aredescribed in detail: a) well control; b) making a connection; c)tripping in and out of the hole using a DDV; d) rate of penetration; e)stuck pipe and loss of circulation; and f) mud logging and open holewell logging.

a) Well Control (Kick and Blowouts)

Operations regarding well control comprise: allowing the well to flow(“influx”) into wellbore and to surface; safely controlling the pressureand flow using special UBD equipment (RCD, UBD choke and 4-phaseseparator; and modeling and monitoring circulating ECD downhole andkeeping pressures below reservoir pressure at all times. Furthermore,operations involving well control should not comprise: closing pipe ramsor annular preventer; evacuating personnel from location when gas isflaring (normal operation); “killing” the well using higher mud weightdrill fluid; and reverting to well control by circulating through rigchoke manifold until flow stops and well is “dead.”

b) Making a Connection

Operations involving making a connection comprise: bypassing nitrogeninjection into well through standpipe & divert gas to reserve pit;continue pumping drilling fluid to displace nitrogen below top drillfloat (“check valve”) in drill pipe; stop rig pumps and make connectionas usual; resume rig pumps and turn nitrogen back to standpipe.

What not to do: Do not “slug” drill pipe with a heavy barite pill toprevent wet connections (no solids in system); never break pipe for aconnection until nitrogen pressure has been displaced below top float.

c) Tripping in and Out of the Hole Using a DDV

What to do: After trip, start stripping back into the wellconventionally without pressure (live well is shut-in beneath DDVflapper); when lower marker sub is noted, bit is just above DDV;equalize pressure across the DDV; open the DDV; slowly strip BHA throughDDV until upper marker sub is noted (well “live”); circulate outpotential gas bubble trapped under DDV; finish stripping to TD underpressure (“live” well) using RCD; start stripping out of well underpressure using RCD to seal against drill pipe; look for upper marker subto indicate position of BHA just below DDV depth; slowly strip BHAthrough DDV until lower marker sub is pulled, showing bit is above DDV;close DDV and bleed off pressure on annulus, then trip out of holeconventionally.

What not to do: Do not forget that DDV flapper is blocking casing ID; donot trip too fast because surge pressure can open DDV prematurely &allow leakage; do not run bit into flapper before opening DDV (willdamage tool); do not forget to equalize pressures across DDV beforetrying to open DDV (will damage tool); do not trip BHA too fast throughDDV (can damage tool); do not forget to circulate out gas bubble thatwas trapped beneath DDV while flapper was closed; do not forget thatwell is “live” with pressure at surface; do not trip BHA through DDVwithout slowing tripping speed (can damage DDV); do not keep pullingpipe without closing DDV after bit is above DDV (avoid “pipe light”condition).

d) Rate of Penetration (ROP)

What to do: UBD causes ROP to double or triple vs. overbalanced drillingtherefore control drill (hold back) penetration rate to avoid excessiveROP; look for unusual increases in ROP which is a positive indication ofincreased fractures.

What not to do: Do not drill as fast as bit will drill as it will resultin excessive quantity of cuttings returning to surface and higher thandesired effective fluid weight that can cause overbalanced pressures.

e) Stuck Pipe and Loss of Circulation

What to do: Stuck pipe and/or losses of circulation mean the pressuresbeing exerted on the reservoir are too high (i.e., the well is no longerunderbalanced), stop drilling until normal conditions return; minimizesurface back-pressure at choke or separator; adjust drilling fluidand/or nitrogen pumping rates to re-establish UBD conditions at lowerECD pressures; pipe will free itself when differential pressure isremoved, then resume drilling.

What not to do: Do not revert to conventional free point and back-offmeasures to free drill pipe; do not spot pipe ease pill to loosen stuckpipe or pump LCM pill to stop losses (will cause solids plugging); donot need costly fishing jobs; do not keep pumping away drilling fluid iflosses are noted . . . will only result in costly drilling fluid lossesand possible damage to reservoir.

f) Mud Logging and Open Hole Well Logging

What to do: Mud logging requires different techniques: Cuttings cannotbe collected coming off shale shakers; must be collected at UBD 4-phaseseparator under pressure (usually very fine samples); gas monitoring atseparator or off gas flare line, not at possum belly (gas will containnitrogen). Usually do not open hole log UBD wells, but can if necessaryunder pressure.

What not to do: Do not allow mud loggers to operate sample catchers at4-phase separator; let service company technicians gather samples due topressure on vessel; do not forget that some formations may containpoisonous hydrogen sulfide gas; take adequate safety precautions.

Example Drilling Program

An example of a drilling program using the disclosed method and systemis as follows:

-   -   1. Stake location.    -   2. Obtain necessary regulatory permits.    -   3. Build all weather road and location for drilling rig.    -   4. Drill water well for rig use or provide alternate water        source.    -   5. Set 16″ conductor at ±40′. Install 8′ OD×5′ deep cellar        (corrugated metal), Drill mousehole and rathole.    -   6. Move in and rig up drilling rig.    -   7. Notify appropriate regulatory entity (e.g. in Texas, the RRC        division) of intent to spud 24 hrs prior to spudding in.    -   8. Build spud mud in working tanks.    -   9. Drill 12¼″ surface hole to 1000′ or depth required by        appropriate regulatory entity. Circulate hole clean and make        clean-up trip to the surface. Measure out of hole. Drill to        1000′. Run one pump until the bottom hole assembly is below the        conductor. Take wireline surveys every 500′.    -   10. Circulate and condition mud.    -   11. Pull out of the hole to run 9⅝″ casing.    -   12. Run float shoe (down jet), 1 joint of 9⅝″ casing, float        collar and 9⅝″ casing as follows:

Interval Length Wt. Grade Coupling 0′-1000′ 1000′ 36#/ft. J-55 STC

-   -   -   Clean and drift casing prior to running. Thread lock from            top of float shoe to top of float collar. Install            centralizer 5′ above shoe, 5′ below the float collar, on            collar of 2nd, 3rd, 4th and 5th joints and then every fourth            collar to the surface (17 centralizers). Have standby tongs            on location.

    -   13. Circulate well clean with a least 1 casing volume or bottoms        up, whichever is greater.

    -   14. Rig up Cementers. Pump 50 barrels of fresh water followed by        cement as per cement proposal.        -   Note:        -   a. Notify the appropriate regulatory entity, as required,            prior to spud and 24 hours prior to setting all casing            strings.        -   b. If cement s not circulated to surface, obtain approval            from the appropriate regulatory entity, prior to topping            out.

    -   15. Wait on cement for 6 hours. Cut off conductor and 9⅝″        casing. Weld on 9⅝″ SOW×11″ 5000 psi bradenhead. Allow weld to        cool and test weld to 1000 psi (collapse rating on 9⅝″ casing is        2020 psi).

    -   16. Nipple up 11″ 5000 psi (double rani) blowout preventers, 11″        5000 psi annular preventer and 5000 psi choke manifold.

It is noted that: Blowout preventers to have 5″ pipe rams on bottom andblind rams on top; Kelly to have an upper and lower Kelly cock valve(with handle available); have on the floor at all times, safety valvesand inside blowout preventers (with subs) to fit all drill stringconnections in use; the blowout preventers will be retested: (1)whenever any seal subject to test pressure is broken (2) at 14-dayintervals; the annular preventer will be functionally operated at leastweekly; pipe and blind rams will be activated during each trip; ablowout preventer pit level drill shall be conducted weekly for eachdrilling crew; all of the blowout preventer test and drills shall berecorded in the daily drilling report.

-   -   17. Test all blowout related equipment with test plug to 5000        psi and 250 psi except the annular preventer, which should be        tested to 2500 psi and 250 psi. All tests are to be recorded on        a pressure-recording chart and emailed to the office immediately        after successful completion of the tests. Install wear ring        (drain BOP stack, prior to installing wear ring).    -   18. Run 8¾″ PDC bit and drill string.    -   19. Tag cement and test casing to 1500 psi (rated at 3520 psi).        Drill 10′ of new formation and test casing seat to 11 ppg EMW.        Report the results to the office immediately after completion of        the test.    -   20. Drill ahead. Run mud as per mud program.    -   21. Drill an 8¾″ hole to 150′ above KOP.    -   22. Trip out to pick up directional tools and RIH. Take surveys        every 250′ while running into the hole.    -   23. Drill curve at 10-12°/100′ BUR. Drill to +/−70°, or until        returns show 100% of targeted formation.    -   24. The following equipment should be operational below surface        casing: power choke, PVT, flow sensor and drilling monitor. Mud        logger should be rigged up and logging at 3000′.    -   25. Make short trips as hole conditions dictate.    -   26. Short trip at intermediate total depth. Circulate and        condition mud. Measure out of the hole.    -   27. Run logs per the logging program: for example: GR/High        Resolution Induction/Spectral Density/Dual Spaced Neutron        (Triple Combo).    -   28. Prior to running the 7″ casing, clean threads and drift.    -   29. After logging, go in the hole and condition mud. POOH LD 5″        drill pipe.    -   30. Run 7″, 23#, L-80, LTC casing. Run casing slowly to reduce        the risk of lost returns. Have standby tongs on location.    -   31. Run float shoe (down jet), 1 joint of 7 casing, float collar        and 7″, 23#, L-80, LTC casing to surface. Thread lock all        connections from top of float shoe to top of float collar. Run        Solid. Body centralizer 5′ above float shoe, 5′ below float        collar, below the collar of each joint to 5700′ and then        bowsprings every other joint to 4600′. Run DDV @6,500′ from        surface. Detailed DDV running procedure may be provided by the        DDV manufacture, i.e. Weatherford.    -   32. Run Cement DV Tool @3,000′ or as required by appropriate        regulatory entity.    -   33. Circulate well clean with at least 1 casing volume.    -   34. Rig up Cementers. Pump Cement as per cementing proposal.    -   35. Displace cement and bump plug with 500 psi above final pump        pressure. Bleed pressure to zero to insure the floats are        holding. The casing should be reciprocated 20′ as long as        possible during circulation and cementing operations. Cement        volume to be calculated from caliper log, using 10% excess.    -   36. Cycle the DDV several times as per Weatherford procedures to        ensure there is no residual cement in the valve or sliding        sleeve.    -   37. Nipple down blowout preventers. Set slips with casing in        full tension.    -   38. Cut off 7″ casing and nipple up 11″ 5000 psi×11″ 5000 psi        casing hanger. Test pack off to 2500 psi (collapse rating of 7″        casing is 3830 psi).    -   39. Nipple up 11″, 5000 psi (double) blowout preventers, 11″        5000 psi annular preventer and 5000 psi choke manifold.    -   40. Rig up UBD 4 phase separator, N2 package, and rotating head        preventer (e.g. Series 7100)    -   41. Test all blowout preventer related equipment to 5000 psi and        250 psi with the exception of the annular preventer, which        should be tested to 2500 psi and 250 psi. All tests are to be        recorded on a circular chart and emailed to the office        immediately after successful completion of the test. Install        wear ring (drain BOP stack).

It is noted that: Blowout preventers to have 3⅕″ pipe rams on bottom andblind rams on top; Kelly to have an upper and lower Kelly cock valve(with handle available); have on the floor at all times, safety valvesand inside blowout preventers (with subs) to fit all drill stringconnections in use; the blowout preventers will be retested: (1)whenever any seal subject to test pressure is broken (2) at 14 dayintervals; the annular preventer will be functionally operated at leastweekly; pipe and blind rams will be activated during each trip; ablowout preventer pit level drill shall be conducted weekly for eachdrilling crew; all of the blowout preventer test and drills shall berecorded in the daily drilling report.

-   -   42. Pick up 3½″ DP. Run 6⅛″ PDC bit and BHA.    -   43. RIH with drill string to 9 joints above DDV. Install Marker        Sub. Continue into the hole until the BRA is 9 joints below the        DDV and install another marker sub. This provides a reference        for the positioning of the DDV during trips.    -   44. Tag cement and test casing to 2500 psi (burst rating at 6340        psi).    -   45. Clean mud tanks Fill with 500 BBLS lease crude. Displace        water base mud with 60 barrels of water followed by lease crude.        Displace at high pump rate and rotate the drill string during        the displacement.

Note: To minimize oil losses during trip and on connections, use a Kellycheck valve, pipe rack drain pans and pipe wiper.

-   -   46. Drill the float collar, cement float shoe and 10′ of new        formation. Circulate bottoms up and condition mud.    -   47. An Underbalanced bottom hole condition will be maintained at        all times during the drilling of the lateral. This will be        monitored using a Pressure While Drilling (PWD) sub in the MWD.        If the drilling fluid column is too heavy, the N2 will be used        to aerate the fluid.    -   48. Drill a 6⅛″ hole to planned TD of 11,000′.    -   49. Monitor and report flow rates in and out, and pressure on        the 4 phase separator.    -   50. If a trip is needed, circulate 2× bottoms up prior to        preparing to trip out. Strip out of the hole using the rotating        head to the 1st marker sub. Pull the BHA to 1 joint above the        DDV. Shut in the well at surface. Close the DDV and pump 10 bbls        of clean fluid across the closed flapper. This will help to        clear any debris from the flapper that would hinder the        metal-to-metal seal. Bleed pressure off at surface and monitor        flow. If hole is static, continue out of the hole and change the        necessary components of the BHA. Trip back in the hole using the        same marker sub method used on the first trip in.    -   51. Trip back in the hole using the same marker sub method used        on the first trip in. When the BHA is above the DDV, close in        the well and cycle the DDV open. If there is pressure below the        valve, it will need to be equalized before the valve will        completely open. Continue stripping into the hole to continue        drilling.    -   52. After reaching total depth, Circulate a minimum of 2×        bottoms up. Shut pumps down and measure natural flow rate from        well. Measure out of the hole.    -   53. Close DDV in same method as stated in #48. Continue out of        the hole.    -   54. TIH and set storm packer@50′.    -   55. Nipple down blowout preventers. Nipple up capping flange.    -   56. Clean mud tanks and release rig. Report volume of produced        oil returned to Purchaser

What is claimed is:
 1. An advanced method of drilling a hydrocarbonwellbore, comprising: using at least one of an overbalanced and anunderbalanced fluid column to drill a wellbore to an upper portion of ahydrocarbon reservoir; installing and cementing a casing string insidethe wellbore to the upper portion of the hydrocarbon reservoir;providing a mechanical fluid control valve in the casing string segmentabove a predetermined target producing zone; using an underbalancedfluid column, drilling and completing the targeted producing zone usinga solids-free and non-wetting phase drilling fluid maintained below thepressure of the hydrocarbon reservoir; injecting nitrogen into thedrilling fluid as needed to reduce the hydrostatic head of the drillingfluid and enable the underbalanced drilling to be maintained; andcirculating the drilling fluid and nitrogen, and any produced fluids androck cuttings, through a series of surface process equipment designed toseparate oil, gas, water and rock cuttings under pressure.
 2. The methodof claim 1, wherein the solids-free and non-wetting phase fluidcomprises a crude oil, a pure mineral oil and an LVT drilling fluid fora water wet reservoir.
 3. The method of claim 1, wherein the nitrogen isinjected into the hydrocarbon wellbore by at least one of the drillstring and through an annulus formed with a casing string.
 4. The methodof claim 3, wherein the solids-free and non-wetting phase fluidcomprises water for an oil wet reservoir.
 5. The method of claim 1,wherein a rotating pressure control device is positioned at a surfacelocation in communication with the drill string, and the mechanicalfluid control valve is positioned at a subsurface location above theproducing formation.
 6. The method of claim 1, wherein nitrogen iscirculated downhole between two strings of casing.
 7. The method ofclaim 1, wherein no drilling or completion fluid which is overbalancedwith respect to the hydrocarbon formation pressure comes in contact withthe hydrocarbon formation.
 8. The method of claim 1, wherein theunderbalanced fluid column is maintained throughout the entire drillingand completion operations.
 9. The method of claim 5, wherein thedownhole deployment valve is interconnected to the lowermost portion ofcasing string.
 10. The method of claim 9, wherein formation cuttings,nitrogen and any wellbore fluid is produced under pressure in theannulus between the drill string and production casing.
 11. A method ofdrilling for recovery of hydrocarbons comprising oil and natural gasfrom a hydrocarbon reservoir, comprising: using an overbalanced orunderbalanced fluid column to drill a hydrocarbon wellbore to an upperportion of a hydrocarbon reservoir; installing and cementing a casingstring inside the wellbore; providing a downhole deployment valve in alowermost casing string segment and above a projected hydrocarbonproducing zone; using an underbalanced fluid column, drilling andcompleting the targeted producing zone using a solids-free andnon-wetting phase drilling fluid maintained below the pressure of thehydrocarbon reservoir; providing nitrogen as needed in the drillingfluid to reduce the hydrostatic head of the drilling fluid; circulatingthe nitrogen through an annulus formed by a second casing; circulatingthe drilling fluid and nitrogen, and any produced fluids and rockcuttings, through surface process equipment designed to separate oil,gas, water and rock cuttings under pressure.
 12. The method of claim 11,wherein the wellbore is configured such that underbalanced conditionsare maintained throughout the entire drilling and completion operations.13. A system for drilling for recovery of hydrocarbons comprising oiland natural gas from a hydrocarbon reservoir, comprising: a wellboreextending at least to an upper portion of a hydrocarbon reservoir; acasing string disposed inside the wellbore; a mechanical fluid controlvalve disposed in the casing string segment and above a target producingzone; utilizing a solids-free and non-wetting phase drilling fluidmaintained below the pressure of the hydrocarbon reservoir; and whereinthe drilling fluid is maintained below the pressure of the hydrocarbonreservoir to enable underbalanced drilling; wherein nitrogen is injectedinto the drilling fluid as needed to reduce the hydrostatic head of thedrilling fluid and enable the underbalanced drilling to be maintained;and wherein nitrogen, hydrocarbons, and drilling fluid are produced andtreated under pressure with surface process equipment.
 14. The system ofclaim 13, wherein the solids-free and non-wetting phase fluid comprises:(a) crude oil, pure mineral oil and LVT drilling fluid for water wet andpartially water wet reservoirs, and (b) water for oil wet reservoirs.15. The system of claim 14, wherein the nitrogen is injected into thewellbore through at least one of a drill string and an annulus in thecasing.
 16. The system of claim 15, wherein the rotating pressurecontrol device is positioned at a surface location, and the mechanicalfluid control valve is deployed subsurface above the hydrocarbonformation.
 17. The system of claim 16, wherein the downhole deploymentvalve is interconnected to the lowermost joint of casing.
 18. The systemof claim 13, wherein the solids-free and non-wetting phase fluidcomprises a crude oil, a pure mineral oil and an LVT drilling fluid fora water wet or partially water wet reservoir.
 19. The system of claim13, wherein no drilling or completion fluid which is overbalanced withrespect to the hydrocarbon formation pressure comes in contact with thehydrocarbon formation.
 20. The system of claim 13, wherein producedhydrocarbons, drilling fluid, water, nitrogen, wellbore cuttings and gasare treated in a pressurized four phase separator at a surface location.